1. Field of the Invention
This invention relates to the treatment of hydrocarbons and more specifically relates to separating and recovering ethane and higher boiling hydrocarbons with a physical solvent from a natural gas stream which is sour or which has been sweetened by removal of acidic components, such as CO.sub.2, H.sub.2 S, RSH, and RSSR, and especially relates to economical separation of C.sub.5 + hydrocarbons from the physical solvent.
2. Review of the Prior Art
Numerous processes have been used to extract liquids from natural gas streams. These processes include oil absorption, refrigerated oil absorption, simple refrigeration, cascaded refrigeration, Joule-Thompson expansion, and cryogenic turbo-expansion. Typical recoveries for these processes are given in Table I.
TABLE 1 ______________________________________ COMPARISON OF TYPICAL LIQUID RECOVERIES ETH- PRO- BU- GASO- EXTRACTION ANE PANE TANES LINE PROCESS (%) (%) (%) (%) ______________________________________ ABSORPTION 4 24 75 87 REFRIGERATED 15 65 90 95 ABSORPTION SIMPLE 35 80 93 97 REFRIGERATION CASCADED 70 96 99 100 REFRIGERATION JOULE-THOMPSON 75 96 99 100 EXPANSION TURBO-EXPANDER 85 97 100 100 ______________________________________
In summary, the oil absorption, refrigerated oil absorption, simple refrigeration, and cascaded refrigeration processes operate at the pipeline pressures, without letting down the gas pressure, but the recovery of desirable liquids (ethane plus heavier components) is quite poor, with the exception of the cascaded refrigeration process which has extremely high operating costs but achieves good ethane and propane recoveries. The Joule-Thompson and cryogenic expander processes achieve high ethane recoveries by letting down the pressure of the entire inlet gas, which is primarily methane (typically 80-85%), but recompression of most of the inlet gas is quite expensive.
In all of the above processes, the ethane plus heavier components are recovered in a specific configuration determined by their composition in the raw natural gas stream and equilibrium at the key operating conditions of pressure and temperature within the process.
Under poor economic conditions when ethane price as petrochemical feedstock is less than its equivalent fuel price and when the propane price for feedstock usage is attractive, the operator of a natural gas liquid extraction plant is limited as to operating choice because he is unable to minimize ethane recovery and maximize propane recovery in response to market conditions.
The refrigeration process which typically recovers 80% of the propane also typically requires the recovery of 35% of the ethane. In order to boost propane recovery to the 95+% level, cascaded refrigeration, Joule-Thompson, or cryogenic turbo-expander processes would have to be used while simultaneously boosting the ethane recovery to 70+% at a considerably larger capital investment.
Extraction processes are available that employ liquids other than hydrocarbon oils for removal of acidic components, including H.sub.2 S and CO.sub.2, and water. These liquids comprise most physical solvents, such as propylene carbonate, N-methyl pyrrolidone, glycerol triacetate, polyethyleneglycol dimethyl ether, triethylolamine, tributyl phosphate, and gamma butyrolactone.
U.S. Pat. No. 3,594,985 describes a process for removing acid gas from a sour natural gas by countercurrently contacting the natural gas with a mixture of dimethyl ethers of polyethylene glycols containing less than 1 weight percent acid gas within two absorption zones operated in series. The rich solvent is flashed to a low pressure, and about 20-95 weight percent of the solvent is passed from the low-pressure flash tank through a cooler to the first absorption zone, with the residual portion of the solvent being sent to a stripping zone wherein essentially all of the hydrogen sulfide is removed. The well-stripped solvent containing essentially no hydrogen sulfide is then fed to the top of the first absorption zone and is next fed to the top of the second absorption zone.
As presented at the 50th Annual Gas Processors Association Convention, Mar. 17-19, 1980, in a paper entitled "High CO.sub.2 --High H.sub.2 S Removal with SELEXOL Solvent" by John W. Sweny, the relative solubility in dimethyl ether of polyethylene glycol (DMPEG) of CO.sub.2 over methane is 15.0 while that of propane over methane is 15.3. The relative solubility in DMPEG of H.sub.2 S over methane is 134 versus 165 for hexane over methane in DMPEG. The relative solubilities in DMPEG of iso and normal butanes and iso and normal pentanes are in between those of propane and H.sub.2 S. These data indicate that if CO.sub.2 and H.sub.2 S are present in a natural gas stream which contains the C.sub.2 + heavier hydrocarbons that are desirable for petrochemical industry feedstocks, substantial quantities of C.sub.2 + hydrocarbons will be lost with CO.sub.2 and H.sub.2 S vent streams when the natural gas stream is treated with DMPEG.
There has nevertheless existed a need for a process wherein C.sub.2 + hydrocarbons and water could be simultaneously removed to any selected degree without also extracting hydrocarbons of lower molecular weight, such as methane. There has additionally existed a need for a process wherein any natural gas, from very sour to entirely sweet, could be handled by the same equipment while simultaneously dehydrating the gas and recovering the heavier hydrocarbons.
These needs have been met by the process which is described in U.S. Pat. No. 4,421,535 and in the parent applications, Ser. Nos. 06/507,564 and 06/532,005, and which is incorporated herein by reference. This process uses physical solvents for extracting ethane and heavier hydrocarbon components and water, if present, from a natural gas stream at any desired ethane recovery from 2% to 98% while recovering 99+% of propane and all heavier hydrocarbons. It can also achieve any desired propane recovery from 2% to 99+% while recovering 99+% of butanes and all heavier hydrocarbons without recovering more than 2% of ethane. The inlet gas pressure can range from 300 psig to 1300 psig and from an ambient temperature of 75.degree. F. to 120.degree. F.
This process produces a liquid hydrocarbon product having a composition which is selectively versatile rather than fixed, as in prior art processes. In consequence, the composition of its hydrocarbon product can be readily adjusted in accordance with market conditions so that profitability of the absorption operation can be maximized at all times and on short notice.
The extraction and recovery process described in U.S. Pat. No. 4,421,535, in Ser. No. 507,564, and in Ser. No. 532,005 uses excessive energy when simultaneously dehydrating residue gas to less than 7 pounds H.sub.2 O per million standard cubic feet and releasing C.sub.5 + hydrocarbons in the atmospheric flashing stage. It is true that when the natural gas contains relatively low quantities of C.sub.5 + components, there is no need for a vacuum flash; atmospheric flashes are satisfactory, and the process works well. However, if the C.sub.5 + hydrocarbons are present in significant quantities in the natural gas, such significant quantities being defined as any amount greater than 0.2 mol or volume percent, the solvent cannot release these hydrocarbons without flashing to a subatmospheric pressure and thus the C.sub.5 + hydrocarbons continue to build up in the solvent until an equilibrium is reached on the order of 14-15% of hydrocarbons by volume in the solvent stream if the solvent regenerator is bypassed to conserve energy consumption.
The presence of these C.sub.5 + hydrocarbons at the top of the extraction tower tends to limit absorption of C.sub.5 + hydrocarbons from the inlet natural gas stream because the C.sub.5 + hydrocarbons present in lean solvent reach an equilibrium with the residue natural gas stream and therefore tend to remain in the residue natural gas stream. In other words, the need to maximize recovery of heavier hydrocarbons requires the lean solvent to contain no more than about one volume percent of C.sub.5 + hydrocarbons and preferably less than 0.5% by volume of C.sub.5 + hydrocarbons. Furthermore, flashing to sub-atmospheric pressure is expensive, and when the C.sub.5 + hydrocarbons content in the inlet gas stream is greater than 0.2 mol percent, this flashing stage does not produce a C.sub.5 + hydrocarbon-free solvent for recycle to the extractor. There is consequently a need for a more economical method for removing these C.sub.5 + hydrocarbons from the near atmospheric pressure solvent.
Another characteristic of the process described in U.S. Pat. No. 4,421,535 and in Ser. Nos. 507,564 and 532,005 is that natural gas in its normally saturated state is stripped of an appreciable amount of water in the extraction stage. This water, carried by the rich solvent through the one or more flashing stages, is then removed by regenerating the entire volume of solvent in a regenerating stage which requires heating the solvent to a temperature of about 300.degree. F. and subsequently cooling it to ambient temperature. Such heating and cooling is also quite expensive, so that there is a need for a less energy-consuming process for simultaneously dehydrating the natural gas stream and selectively removing its C.sub.2 + hydrocarbon content.